Methods Relating to Modifying Flow Patterns Using In-Situ Barriers

ABSTRACT

A method comprises providing a fluid source in a subterranean formation; providing a wellbore in the subterranean formation; and providing an in-situ barrier, wherein the in-situ barrier is disposed within the subterranean environment and modifies the flow pattern of at least one fluid within the subterranean formation that is provided by the fluid source and flows towards the wellbore.

BACKGROUND

The present invention relates generally to hydrocarbon production, and more particularly to a method of increasing hydrocarbon production in an existing well by forming an in-situ barrier to the flow of one or more fluids to modify flow patterns.

In certain subterranean formations, fluid is injected into a reservoir to displace or sweep the hydrocarbons out of the reservoir. This method of stimulating production is sometimes referred to as a method of “Enhanced Oil Recovery” (“EOR”) and may be called water flooding, gas flooding, steam injection, etc. For the purpose of this specification, the general process will be defined as injecting a fluid (gas or liquid) into a reservoir in order to displace, drive, or increase the production of the existing hydrocarbons into a producing well. The primary issue with injecting fluid to enhance oil recovery is how to sweep the reservoir of the hydrocarbon in the most efficient manner possible. Because of geological differences in a reservoir, the permeability within the reservoir may not be homogenous. Because of such permeability differences between the vertical and horizontal directions or the existence of higher permeability streaks, the injecting fluid may bypass some of the reservoir and create a path into the producing well.

The industry has come up with methods to improve the sweep efficiency in individual wells. These methods include fracturing and the use of deviated wells. The industry currently uses horizontal wells as injectors in an attempt to expose more of the reservoir to the injecting fluid. The goal is to create a movement of injection fluid evenly across the reservoir. This is sometimes referred to as line drive.

Part of the efficiency of the sweep is reducing the production of the injection fluid. The industry has created several techniques involving the use of chemicals that block the injection fluid, to injection fluids that improve the matrix flow through the reservoir to reduce channeling. As used herein, “channeling” refers to a condition in which a fluid flows through a high permeability pathway rather than flowing uniformly through a region or zone. Some injection programs include attempts to plug high permeability streaks and natural fractures in the reservoir. This is done to force the injection fluid out into more of the reservoir to displace hydrocarbons.

When the injection fluid is produced, such as water, it is usually removed from the hydrocarbons at the surface using multi-phase separation devices. A drawback of these devices is that they can require additional maintenance or repair if solids are part of the produced fluid stream. A further, and perhaps greatest drawback of these solutions, is that they do not increase or maximize the amount of hydrocarbons being produced. Their focus is removing the water from the production.

Specialized downhole tools have also been developed, which separate the water from the hydrocarbons downhole. These tools are designed to leave the water in the formation as the hydrocarbons are produced. While these devices can remove a significant amount of water from the hydrocarbons, they are also often less than perfect in removing the water from the hydrocarbons. They also suffer from the same drawback of the surface separation devices in that they do nothing to increase or maximize the amount of hydrocarbons being produced.

SUMMARY

The present invention relates generally to hydrocarbon production, and more particularly to a method of increasing hydrocarbon production in an existing well by forming an in-situ barrier to the flow of one or more fluids to modify flow patterns.

In an embodiment, a method comprises providing a fluid source in a subterranean formation; providing a wellbore in the subterranean formation; and providing an in-situ barrier, wherein the in-situ barrier is disposed within the subterranean environment and modifies the flow pattern of at least one fluid within the subterranean formation that is provided by the fluid source and flows towards the wellbore.

In another embodiment, a method comprises providing a plurality of wellbores in a subterranean formation, wherein at least one wellbore comprises a fracture; providing at least one injection wellbore in the subterranean formation; and providing an in-situ barrier by disposing a sealant in the fracture of the at least one wellbore; wherein the sealant modifies the flow pattern of at least one fluid provided by the injection wellbore within the subterranean formation.

In still another embodiment, a system comprises a fluid source within a subterranean formation for providing a fluid driving force within the subterranean formation; a wellbore disposed in the subterranean formation for producing a production fluid from the subterranean formation; and an in-situ barrier disposed within the subterranean formation, wherein the in-situ barrier modifies the flow of at least one fluid driven by the fluid driving force within the subterranean formation.

The features and advantages of the present invention will be apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments of the present invention, and should not be used to limit or define the invention.

FIG. 1 illustrates a cross-sectional view of an embodiment of a subterranean environment with a wellbore disposed therein.

FIG. 2 illustrates another cross-sectional view of an embodiment of a subterranean environment with a wellbore disposed therein.

FIG. 3 illustrates an aerial view of a water saturation profile of a subterranean formation.

FIG. 4 illustrates an aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.

FIG. 5 illustrates a set of simulated results for total oil production according to an embodiment of the present invention.

FIG. 6 illustrates a set of simulated results for total water production according to an embodiment of the present invention.

FIG. 7 illustrates a side view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.

FIG. 8 illustrates an aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.

FIG. 9 illustrates a set of simulated results for total oil production according to an embodiment of the present invention.

FIG. 10 illustrates a set of simulated results for total water production according to an embodiment of the present invention.

FIG. 11 illustrates an aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.

FIG. 12 illustrates an aerial view of a water saturation profile of a subterranean formation.

FIG. 13 illustrates a set of simulated results for total oil production according to an embodiment of the present invention.

FIG. 14 illustrates a set of simulated results for total water production according to an embodiment of the present invention.

FIG. 15 illustrates an aerial view of a simulated subterranean wellbore layout useful to show an embodiment of the present invention.

FIG. 16 illustrates an aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.

FIG. 17 illustrates another aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.

FIG. 18 illustrates still another aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention relates generally to hydrocarbon production, and more particularly to a method and system for increasing hydrocarbon production in an existing well by forming an in-situ barrier to the flow of one or more fluids to modify flow patterns.

The methods and systems disclosed herein may be advantageously used to modify the flow pattern within a reservoir to increase the amount of hydrocarbons recovered from the subterranean formation and decreasing the amount of water produced from the subterranean formation. The system and method described herein may be used with an existing well in an existing formation to allow for the additional recovery of hydrocarbons without having to drill new wells, though new wells can be used in an embodiment. A number of exemplary ways of performing these functions are disclosed herein.

In an embodiment, the present invention improves the production efficiency of hydrocarbons from a producing reservoir by: providing a fluid source in a subterranean formation, providing a wellbore in the subterranean formation, providing an in-situ barrier in the subterranean formation that modifies the flow pattern of at least one fluid provided by the fluid source that flows toward the wellbore.

The present invention provides improved methods, systems, and materials for modifying the flow pattern in a reservoir. The methods, systems, and materials can be used in either vertical, deviated or horizontal wellbores, in consolidated and unconsolidated formations, in “open-hole” and/or under reamed completions, as well as in cased wells. If used in a cased wellbore, the casing may be perforated to provide for fluid communication between the wellbore and the subterranean formation. The term “vertical wellbore” is used herein to mean the portion of a wellbore to be completed which is substantially vertical or deviated from vertical in an amount up to about 15°. The term “horizontal wellbore” is used herein to mean the portion of a wellbore to be completed which is substantially horizontal, or at an angle from vertical in the range of from about 75° to about 105°. All other angular positioning relates to a deviated or inclined wellbore. Since the present invention is applicable in horizontal and inclined wellbores, the terms “upper and lower” and “top and bottom” as used herein are relative terms and are intended to apply to the respective positions within a particular wellbore, while the term “levels” is meant to refer to respective spaced positions along the wellbore. In the present description, the terms “upper,” “top,” and “above” refer to the portion of a wellbore nearer to the surface or wellhead while the terms “lower,” “bottom,” and “below” refer to the portion of a wellbore further from the surface or wellhead, irrespective of the true vertical depth of any portion of the wellbore.

The present invention can be used in forming an in-situ barrier to fluid flow in a subterranean formation. For purposes of illustration, the present invention may be described in the context of a typical water contamination problem in which water is produced with the hydrocarbons. However, the methods and materials of the present invention may have application to other situations where blocking the flow of fluids other than water or all fluids is needed. Such applications include, without limitation, any EOR operation including water flooding, gas flooding, steam injection, in-situ combustion operations, or any other operation designed to increase the production of hydrocarbons using a fluid.

Referring more particularly to the drawing, FIG. 1 illustrates a wellbore 110 for producing hydrocarbons from a subterranean formation. Wellbore 110 can be drilled using conventional drilling techniques, for example directional drilling techniques or other similar methods. The precise method used is not an important aspect of the present invention. In one certain exemplary embodiment, the wellbore 110 lined with a casing string. The casing string may then be cemented to the formation. There are a number of factors that go into the decision of whether to case the wellbore 110 and whether to cement the casing to the formation. A person of ordinary skill in the art should know whether the wellbore 110 needs to be cased. In most cases, it will be beneficial to do so.

The wellbore 110 may extend through a hydrocarbon-containing subterranean formation area 112 and into a water-bearing area 114. As used herein, the term “water” refers to any aqueous fluid and may include, for example, fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated saltwater), or any combination thereof. As is commonly known in the art, there is generally no distinct water-hydrocarbon boundary. The boundary may be more like an area composed of a mixture of varying proportions of water and hydrocarbons. For the purpose of description, the water-hydrocarbon boundary area is illustrated as a broad line 116, it being understood, of course, that the water-hydrocarbon boundary area may be much more irregular and larger than the line. In an embodiment, the water may come from a variety of sources, including but not limited to, in-situ water, injected water, or water entering the reservoir from an external source. For example, the water may be introduced into the formation through an injection wellbore 124 that may inject water into the reservoir through one or more fractures 126 as part of an EOR operation.

The lower end of the wellbore is illustrated extending to a location beneath the boundary 116. Typically, as hydrocarbons are produced (removed) from the area surrounding the well, the water boundary 116 rises until it is in contact with fractures at the lower end of the wellbore 118. Indeed, hydrocarbons can be produced at a rate that will cause the water boundary to extend upward or “cone” around the wellbore, speeding up the production of significant volumes of water with the hydrocarbons.

According to the present invention, a fracture 120 is opened up to extend from the wellbore and may generally be located above the water boundary 116. The fracture 120 in this case is generally disk shaped extending from the wellbore 110 in all directions. As will be described, fracturing technology exists to create open fractures from wellbores extending in selected directions, distances and having selected shapes. In an embodiment, the fracture is formed to extend from all sides about 500 ft to about 1,000 ft from the wellbore though longer fractures may be possible. In this embodiment, the fracture 120 is filled with a sealant 122. Any fractures located below the water boundary, for example, fracture 118, may also be filled with a sealant. The sealant 122 may be pumped into the fracture 120 as part of a treatment fluid, for example, in a slurry form and also into any flow paths in the form of voids intersecting the fracture 120.

One or more fractures may be formed in or along the wellbore 110 using a variety of techniques. In one exemplary embodiment, the plurality of fractures are formed by using a hydra jetting tool, such as that used in the SurgiFrac® fracturing service offered by Halliburton Energy Services in Duncan, Okla. In this embodiment, the hydra jetting tool forms each fracture, one at a time. Each fracture may be formed by the following steps: (i) positioning the hydra jetting tool in the wellbore at the location where the fracture is to be formed, (ii) perforating the reservoir at the location where the fracture is to be formed, and (iii) injecting a fracture fluid into the perforation at sufficient pressure to form a fracture along the perforation. As those of ordinary skill in the art will appreciate, there are many variations on this embodiment. For example, fracture fluid can be simultaneously pumped down the annulus while it is being pumped out of the hydra jetting tool to initiate the fracture. Alternatively, the fracturing fluid may be pumped down the annulus and not through the hydra jetting tool to initiate and propagate the fracture. In this version, the hydra jetting tool primarily forms the perforations.

In an embodiment, one or more fractures may be formed by staged fracturing. Staged fracturing may be performed by a method comprising (i) detonating a charge in the wellbore 110 at the location where a fracture is to be formed so as to form at least one perforation in the reservoir at that location, (ii) pumping a fracture fluid into the perforation at sufficient pressure to propagate the fracture, (iii) installing a plug in the wellbore uphole of the fracture, (iv) repeating steps (i) through (iii) until the desired number of fractures have been formed; and (v) removing the plugs following the completion of step (iv). As those of ordinary skill in the art will appreciate, there are many variants on the staged fracture method.

The fractures may take a variety of geometries including, but not limited to, transverse fractures, longitudinal fractures (e.g., curtain wall fractures), or fractures extending at an angle with respect to the wellbore longitudinal axis (e.g., deviated fractures that may extend along natural fracture lines). In some embodiments, the fractures may be formed along natural fracture lines and may generally be parallel to one another. The fracture's shape, size and orientation can be determined by the orientation of the fluid nozzles and movement thereof. Using hydrajetting radially from a vertical wellbore, a transversely extending fracture can be formed and may extend from about 50 ft to about 1000 ft from the wellbore. In other applications such as water flooding, longitudinal extending fractures (e.g., parallel to the wellbore) may be formed to create a curtain wall fracture that may be used to form a curtain wall in-situ barrier. In an embodiment, fractures used to form in-situ barriers in multiple adjacent wells may be used to form co-operating in-situ barriers.

After the wellbore 110 has been cased and a fracture has been formed, the fracture may have a sealant disposed therein. The sealant may be disposed in the fracture by squeezing it into the fracture. This may be accomplished by first isolating the perforations adjacent to the fracture using a packer (e.g., a hydraulically set drillable, retrievable or inflatable packer) on the end of tubing and setting the packer in the casing; then pumping the sealant in a fluid state through the tubing, then through the perforations and into the fracture to be sealed until a sufficient volume of sealant has been placed into the transverse fracture to provide the in-situ barrier to flow.

In an embodiment, the sealant used to provide the in-situ barrier may be any material capable of selectively or non-selectively reducing the flow of one or more fluids within a subterranean formation. As used in this context a non-selective barrier is an in-situ barrier intended to substantially seal the fracture. A selective barrier is an in-situ barrier intended to modify the permeability or relative permeability (as described above) to allow fluids to selectively flow through the fracture. The sealant may comprise a cement, a linear polymer mixture, a linear polymer mixture with cross-linker, an in-situ polymerized monomer mixture, a resin-based fluid, an epoxy based fluid, a magnesium based slurry, a clay based slurry (e.g., a bentonite based slurry), an emulsion, a precipitate (e.g., a polymeric precipitate), or an in-situ precipitate. As used herein, an in-situ precipitate is a precipitate formed within the subterranean formation, for example, using a polymeric solution that is introduced into a subterranean formation followed by an activator. All of these sealants are capable of being placed in a fluid state with the property of becoming a viscous fluid or solid barrier to fluid migration after or during placement into the fracture. In one embodiment, the sealant is H₂Zero™ available from Halliburton Energy Services, Inc., Duncan, Okla. Other sealants could include particles, drilling mud, cuttings, and slag. Exemplary particles could be ground cuttings so that a wide range of particle sizes would exist and produce a low permeability as compared to the surrounding reservoir. As used herein, the term drilling mud includes all types of drilling mud known to those of ordinary skill in the art including, but not limited to, oil based muds, invert emulsions, polymer based muds, clay based muds (e.g., bentonite based drilling mud), and weighted muds.

In an embodiment, the sealant may comprise swellable particles. As used herein, a particle is characterized as swellable when it swells upon contact with an aqueous fluid (e.g., water), an oil-based fluid (e.g., oil), or a gas. Suitable swellable particles are described in the following references, each of which is incorporated by reference herein in its entirety: U.S. Pat. No. 3,385,367, U.S. Pat. No. 7,059,415, U.S. Pat. No. 7,578,347, U.S. Pat. App. No. 2004/0020662, U.S. Pat. App. No. 2007/0246225, U.S. Pat. App. No. 2009/0032260 and WO2005/116394.

Swellable particles suitable for use with embodiments of the present invention may generally swell by up to about 200% of their original size at the surface. Under downhole conditions, this swelling may be more, or less, depending on the conditions present. For example, the swelling may be at least 10% under downhole conditions. In some embodiments, the swelling may be up to about 50% under downhole conditions. Although the rate of swelling may be hours in some embodiments, in certain embodiments the rate of swelling may be measured in minutes. The rate of swelling is defined as the amount of time required for the swelled composition to substantially reach an equilibrium state, where swelling is within 5% of its final equilibrium state. However, as those of ordinary skill in the art, with the benefit of this disclosure, will appreciate, the actual swelling when the swellable particles are included in a sealant may depend on, for example, the concentration of the swellable particles included in the sealant, the temperature, the pressure, and the other components present in the wellbore.

An example of a swellable particle that may be suitable for use with embodiments of the present invention comprises a swellable elastomer that swells in the presence of an oil-based fluid or an aqueous-based fluid. Some specific examples of suitable swellable elastomers that swell in the presence of an oil-based fluids include, but are not limited to, natural rubbers, acrylate butadiene rubbers, isoprene rubbers, chloroprene rubbers, butyl rubbers, brominated butyl rubbers, chlorinated butyl rubbers, chlorinated polyethylenes, neoprene rubbers, styrene butadiene copolymer rubbers, chlorinated polyethylene, sulphonated polyethylenes, ethylene acrylate rubbers, epichlorohydrin ethylene oxide copolymers, epichlorohydrin terpolymer, ethylene-propylene rubbers, ethylene vinyl acetate copolymers, ethylene-propylene-diene terpolymer rubbers, ethylene vinyl acetate copolymer, nitrile rubbers, acrylonitrile butadiene rubbers, hydrogenated acrylonitrile butadiene rubbers, carboxylated high-acrylonitrile butadiene copolymers, polyvinylchloride-nitrile butadiene blends, fluorosilicone rubbers, silicone rubbers, poly 2,2,1-bicyclo heptenes (polynorbornene), alkylstyrenes, polyacrylate rubbers such as ethylene-acrylate copolymer, ethylene-acrylate terpolymers, fluorocarbon polymers, copolymers of poly(vinylidene fluoride) and hexafluoropropylene, terpolymers of poly(vinylidene fluoride), hexafluoropropylene, and tetrafluoroethylene, terpolymers of poly(vinylidene fluoride), polyvinyl methyl ether and tetrafluoroethylene, perfluoroelastomers such as tetrafluoroethylene perfluoroelastomers, highly fluorinated elastomers, butadiene rubber, polychloroprene rubber, polyisoprene rubber, polynorbornenes, polysulfide rubbers, polyurethanes, silicone rubbers, vinyl silicone rubbers, fluoromethyl silicone rubber, fluorovinyl silicone rubbers, phenylmethyl silicone rubbers, styrene-butadiene rubbers, copolymers of isobutylene and isoprene known as butyl rubbers, brominated copolymers of isobutylene and isoprene, chlorinated copolymers of isobutylene and isoprene, and any combination thereof. An example of a commercially available product comprising such swellable particles may include a commercially available product from Easy Well Solutions of Norway, under the trade name “EASYWELL.”

Suitable examples of useable fluoroelastomers that swell in the presence of an oil-based fluid are copolymers of vinylidene fluoride and hexafluoropropylene and terpolymers of vinylidene fluoride, hexafluoropropylene and tetrafluoroethylene. The fluoroelastomers suitable for use in the disclosed invention are elastomers that may comprise one or more vinylidene fluoride units (“VF₂” or “VdF”), one or more hexafluoropropylene units (“HFP”), one or more tetrafluoroethylene units (“TFE”), one or more chlorotrifluoroethylene (“CTFE”) units, and/or one or more perfluoro(alkyl vinyl ether) units (“PAVE”), such as perfluoro(methyl vinyl ether) (“PMVE”), perfluoro(ethyl vinyl ether) (“PEVE”), and perfluoropropyl vinyl ether (“PPVE”). These elastomers can be homopolymers or copolymers. Particularly suitable are fluoroelastomers containing vinylidene fluoride units, hexafluoropropylene units, and, optionally, tetrafluoroethylene units and fluoroelastomers containing vinylidene fluoride units, perfluoroalkyl perfluorovinyl ether units, and tetrafluoroethylene units, such as the vinylidene fluoride type fluoroelastomer known under the trade designation “AFLAS®” available from Asahi Glass Co., Ltd. Of Tokyo, Japan. Especially suitable are copolymers of vinylidene fluoride and hexafluoropropylene units. If the fluoropolymers contain vinylidene fluoride units, the polymers may contain up to 40 mole % VF₂ units, e.g., 30-40 mole %. If the fluoropolymers contain hexafluoropropylene units, the polymers may contain up to 70 mole % HFP units. If the fluoropolymers contain tetrafluoroethylene units, the polymers may contain up to 10 mole % TFE units. When the fluoropolymers contain chlorotrifluoroethylene the polymers may contain up to 10 mole % CTFE units. When the fluoropolymers contain perfluoro(methyl vinyl ether) units, the polymers may contain up to 5 mole % PMVE units. When the fluoropolymers contain perfluoro(ethyl vinyl ether) units, the polymers may contain up to 5 mole % PEVE units. When the fluoropolymers contain perfluoro(propyl vinyl ether) units, the polymers may contain up to 5 mole % PPVE units. The fluoropolymers may contain 66%-70% fluorine. One suitable commercially available fluoroelastomer is that known under the trade designation “TECHNOFLON FOR HS®” sold by Ausimont USA of Thorofare, N.J. This material contains “Bisphenol AF” manufactured by Halocarbon Products Corp. of River Edge, N.J. Another commercially available fluoroelastomer is known under the trade designation “VITON® AL 200,” by DuPont Performance Elastomers of La Place, La., which is a terpolymer of VF₂, HFP, and TFE monomers containing 67% fluorine. Another suitable commercially available fluoroelastomer is “VITON® AL 300,” by DuPont Performance Elastomers of La Place, La. A blend of the terpolymers known under the trade designations “VITON® AL 300” and “VITON® AL 600” can also be used (e.g., one-third AL-600 and two-thirds AL-300); both are available from DuPont Performance Elastomers of La Place, La. Other useful elastomers include products known under the trade designations “7182B” and “7182D” from Seals Eastern of Red Bank, N.J.; the product known under the trade designation “FL80-4” available from Oil States Industries, Inc. of Arlington, Tex.; and the product known under the trade designation “DMS005” available from Duromould, Ltd. of Londonderry, Northern Ireland.

One process for making a swellable elastomer useful in the present invention may involve grafting an unsaturated organic acid molecule. A common example of an unsaturated organic acid used for this purpose is maleic acid. Other molecules that can be used include mono- and di-sodium salts of maleic acid and potassium salts of maleic acid. Although in principle other unsaturated carboxylic acids may also be grafted onto commercial unsaturated elastomers, acids that exist in solid form may not require additional steps or manipulation, as will be readily apparent to those having reasonable skill in the chemical art. Mixing other unsaturated acids such as acrylic acid and methacrylic acid is also possible but may be more difficult since they are liquids at room temperature. Unsaturated acids such as palmitoleic acid, oleic acid, linoleic acid, and linolenic acid may also be used. The initial reaction leads to a relatively non-porous “acid-grafted rubber.” In order to enhance the swelling of elastomers, addition of a small amount of alkali such as soda ash, along with or separate from the unsaturated acid, leads to formation of a porous, swellable acid grafted rubber. Micro-porosities are formed in the composition, allowing a fluid to rapidly reach the interior region of a molded part and increase the rate and extent of swelling. An organic peroxide vulcanizing agent may be employed to produce a vulcanized, porous, swellable acid-grafted rubber formulation. In one embodiment, 100 phr of EPDM, 5-100 phr of maleic acid, 5-50 phr of sodium carbonate, and 1-10 phr of dicumyl peroxide as vulcanizing agent showed at least 150 percent swelling of elastomer when exposed to both water at 100° C. for 24 hrs and at room temperature for 24 hrs in kerosene. Other commercially available grades of organic peroxides, as well as other vulcanization agents, may be employed. The resulting elastomeric compositions may be described as non-porous, or porous and swelled, acid-grafted rubbers, which may or may not be vulcanized. The terms “vulcanized” and “crosslinked” are used interchangeably herein, although vulcanization technically refers to a physicochemical change resulting from crosslinking of the unsaturated hydrocarbon chain of polyisoprene with sulfur, usually with the application of heat. The relatively hydrophobic linear or branched chain polymers and relatively hydrophilic water-soluble monomers, either grafted onto the polymer backbone or blended therein, may act together to cost-effectively increase the water- and/or oil-swellability of oilfield elements that comprise one or more apparatus of the invention. In particular, the use of unsaturated organic acids, anhydrides, and their salts (for example maleic acid, maleic anhydride, and theirs salts), offer a commercially feasible way to develop inexpensive composites materials with good water, and/or hydrocarbon fluid swellability, depending on the type of inorganic additives and monomers used.

Elastomers such as nitrile rubber, hydrogenated nitrile rubber (HNBR), fluoroelastomers, or acrylate-based elastomers, or their precursors, if added in variable amounts to an EPDM polymer or its precursor monomer mixture, along with a sufficient amount (from about 1 to 10 phr) of an unsaturated organic acid, anhydride, or salt thereof, such as maleic acid, optionally combined with a sufficient amount (from 1 about to 10 phr) an inorganic swelling agent such as sodium carbonate, may produce a water-swellable elastomer having variable low-oil swellability. Addition to the monomer mixture, or to the elastomer after polymerization, of a sufficient amount (from about 0.5 to 5 phr) of a highly acidic unsaturated compound such as 2-acrylamido-2-methylpropane sulfonic acid (AMPS), results in a water-swellable elastomer having variable oil-swellability, and which is further swellable in low pH fluids such as completion fluids containing zinc bromide. A second addition of a sufficient amount (from 1 to 10 phr more than the original addition) of inorganic swelling agent enhances swellability in low pH, high concentration brines. Finally, the addition of a sufficient amount (from 1 to 20 phr) of zwitterionic polymer or copolymer of a zwitterionic monomer with an unsaturated monomer, results in a cross-linked elastomer. The amounts of the various ingredients at each stage may be varied as suited for the particular purpose at hand. For example, if one simply wishes to produce a highly cross-linked, moderately water-swellable (about 100 percent swell) elastomer having very low oil-swellability but very high swellability in low pH fluids, one would use a recipe of 60 to 80 phr of EPDM, and 20 to 40 phr of nitrile or HNBR, and 4 to 5 phr of AMPS, as well as about 15 to 20 phr of a zwitterionic polymer or monomer.

Another reaction scheme useful in the present invention, enabling a low-cost procedure for making swellable elastomers, involves the use of AMPS monomer and like sulfonic acid monomers. Since AMPS monomer is chemically stable up to at least 350° F. (177° C.), mixtures of EPDM and AMPS monomer which may or may not be grafted on to EPDM will function as a high-temperature resistant water-swellable elastomer. The use of AMPS and like monomers maybe used in like fashion to functionalize any commercial elastomer to make a high-temperature water-swellable elastomer. An advantage of using AMPS is that it is routinely used in oilfield industry in loss circulation fluids and is very resistant to down hole chemicals and environments.

Other swellable elastomers that behave in a similar fashion with respect to aqueous fluids also may be suitable. Some specific examples of suitable swellable elastomers that swell in the presence of an aqueous-based fluid, include, but are not limited to starch-polyacrylate acid graft copolymer, polyvinyl alcohol cyclic acid anhydride graft copolymer, polyacrylamide, poly(acrylic acid-co-acrylamide), poly(2-hydroxyethyl methacrylate), poly(2-hydroxypropyl methacrylate), isobutylene maleic anhydride, acrylic acid type polymers, vinylacetate-acrylate copolymer, polyethylene oxide polymers, carboxymethyl cellulose type polymers, starch-polyacrylonitrile graft copolymers and the like, and highly swelling clay minerals such as sodium bentonite having montmorillonite as main ingredient, and any combination thereof.

Additional water swellable particles may comprise particulate matter embedded in a matrix material. One example of such particulate matter is salt, preferably dissociating salt, which can be uniformly compounded into a base rubber. Suitable salts may include, but are not limited to, acetates, bicarbonates, carbonates, formates, halides (M×Hy) (H=Cl, Br or I), hydrosulphides, hydroxides, imides, nitrates, nitrides, nitrites, phosphates, sulphides, sulphates, and any combination thereof. Also, other salts can be applied wherein the cation is a non-metal like NH₄Cl. CaCl₂ may be useful in view of its divalent characteristic and because of its reduced tendency to leach out from a base rubber due to reduced mobility of the relatively large Ca atom in the base rubber.

To limit leaching out of the salt from the swellable elastomer, suitably the swellable particles include a hydrophilic polymer containing polar groups of either oxygen or nitrogen in the backbone or side groups of the polymer matrix material. These side groups can be partially or fully neutralized. Hydrophilic polymers of such type are, for example, alcohols, acrylates, methacrylates, acetates, aldehydes, ketones, sulfonates, anhydrides, maleic anhydrides, nitriles, acrylonitriles, amines, amides, oxides (polyethylene oxide), cellulose types including all derivatives of these types, all copolymers including one of the above all grafted variants. In one instance, a ternary system may be applied which includes an elastomer, a polar SAP and a salt, whereby the polar SAP is grafted onto the backbone of the elastomer. Such system has the advantage that the polar SAP particles tend to retain the salt particles in the elastomer matrix thereby reducing leaching of the salt from the elastomer. The polar salt is attracted by electrostatic forces to the polar SAP molecules which are grafted onto the backbone of the rubber.

Combinations of suitable swellable elastomers may also be used. In certain embodiments, some of the elastomers that swell in oil-based fluids may also swell in aqueous-based fluids. Suitable elastomers that may swell in both aqueous-based and oil-based fluids, include, but are not limited to ethylene propylene rubbers, ethylene-propylene-diene terpolymer rubbers, butyl rubbers, brominated butyl rubbers, chlorinated butyl rubbers, chlorinated polyethylene, neoprene rubbers, styrene butadiene copolymer rubbers, sulphonated polyethylenes, ethylene acrylate rubbers, epichlorohydrin ethylene oxide copolymer, silicone rubbers and fluorosilicone rubbers, and any combination thereof. Those of ordinary skill in the art, with the benefit of this disclosure, will know the appropriate fluid to use in order to swell the a particular swellable elastomer composition.

In certain embodiments, the swellable elastomers may be crosslinked and/or lightly crosslinked. Other swellable elastomers that behave in a similar fashion with respect to fluids may also be suitable. Those of ordinary skill in the art, with the benefit of this disclosure, will be able to select appropriate swellable elastomers based on a variety of factors, including the application in which the composition will be used and the desired swelling characteristics.

Where used, the swellable particles generally may be included in the embodiments of the sealant in an amount sufficient to provide the desired barrier properties. In some embodiments, the swellable particles may be placed in a fracture or void in a treatment fluid comprising an amount up to about 50% by volume of the treatment fluid. In some embodiments, the swellable particles may be present in a range of about 5% to about 95% by volume of the treatment fluid used to place the particles.

In addition, the swellable particles that are utilized may have a wide variety of shapes and sizes of individual particles suitable for use with embodiments of the present invention. By way of example, the swellable particles may have a well-defined physical shape as well as an irregular geometry, including the physical shape of platelets, shavings, fibers, flakes, ribbons, rods, strips, spheroids, beads, pellets, tablets, or any other physical shape. In some embodiments, the swellable particles may have a particle size in the range of about 5 microns to about 1,500 microns. In some embodiments, the swellable particles may have a particle size in the range of about 20 microns to about 500 microns. However, particle sizes outside these defined ranges also may be suitable for particular applications.

In an embodiment, the sealant may comprise a cement. Any suitable cement known in the art may be used as the sealant. An example of a suitable cement includes hydraulic cement, which may comprise calcium, aluminum, silicon, oxygen, and/or sulfur and which sets and hardens by reaction with water. Examples of hydraulic cements include, but are not limited to a Portland cement, a pozzolan cement, a gypsum cement, a high alumina content cement, a silica cement, a high alkalinity cement, or combinations thereof. Preferred hydraulic cements are Portland cements of the type described in American Petroleum Institute (API) Specification 10, 5^(th) Edition, Jul. 1, 1990, which is incorporated by reference herein in its entirety. The cement may be, for example, a class A, B, C, G, or H Portland cement. Another example of a suitable cement is microfine cement, for example, MICRODUR RU microfine cement available from Dyckerhoff GmBH of Lengerich, Germany. Combinations of cements and swellable particles may also be used.

In an embodiment, the sealant may comprise a water soluble relative permeability modifier. As used herein, “relative permeability modifier” refers to a compound that is capable of reducing the permeability of a subterranean formation to aqueous-based fluids without substantially changing its permeability to hydrocarbons. Generally, the water-soluble relative permeability modifiers suitable for use with the present invention may be any suitable water-soluble relative permeability modifier that is suitable for use in subterranean operations. In some embodiments, the water-soluble relative permeability modifiers comprise a hydrophobically modified polymer. As used herein, “hydrophobically modified” refers to the incorporation into the hydrophilic polymer structure of hydrophobic groups, wherein the alkyl chain length is from about 4 to about 22 carbons. In other embodiments, the water-soluble relative permeability modifiers comprise a hydrophilically modified polymer. As used herein, “hydrophilically modified” refers to the incorporation into the hydrophilic polymer structure of hydrophilic groups. In yet another embodiment, the water-soluble relative permeability modifiers comprise a water-soluble polymer without hydrophobic or hydrophilic modification.

The hydrophobically modified polymers suitable for use in the present invention typically have molecular weights in the range of from about 100,000 to about 10,000,000. In some embodiments, a mole ratio of a hydrophilic monomer to the hydrophobic compound in the hydrophobically modified polymer is in the range of from about 99.98:0.02 to about 90:10, wherein the hydrophilic monomer is a calculated amount present in the hydrophilic polymer. In certain embodiments, the hydrophobically modified polymers may comprise a polymer backbone, the polymer backbone comprising polar heteroatoms. Generally, the polar heteroatoms present within the polymer backbone of the hydrophobically modified polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous.

In an embodiment, the hydrophobically modified polymers may be a reaction product of a hydrophilic polymer and a hydrophobic compound. The hydrophilic polymers suitable for forming the hydrophobically modified polymers used in the present invention should be capable of reacting with hydrophobic compounds. Suitable hydrophilic polymers include, homo-, co-, or terpolymers such as, but not limited to, polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols), and alkyl acrylate polymers in general. Additional examples of alkyl acrylate polymers include, but are not limited to, polydimethy laminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl propane sulfonic acid/dimethylaminoethyl methacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylaminopropyl methacrylamide). In certain embodiments, the hydrophilic polymers comprise a polymer backbone and reactive amino groups in the polymer backbone or as pendant groups, the reactive amino groups capable of reacting with hydrophobic compounds. In some embodiments, the hydrophilic polymers comprise dialkyl amino pendant groups. In some embodiments, the hydrophilic polymers comprise a dimethyl amino pendant group and at least one monomer comprising dimethylaminoethyl methacrylate or dimethylaminopropyl methacrylamide. In certain embodiments, the hydrophilic polymers comprise a polymer backbone, the polymer backbone comprising polar heteroatoms, wherein the polar heteroatoms present within the polymer backbone of the hydrophilic polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous. Suitable hydrophilic polymers that comprise polar heteroatoms within the polymer backbone include homo-, co-, or terpolymers, such as, but not limited to, celluloses, chitosans, polyamides, polyetheramines, polyethyleneimines, polyhydroxyetheramines, polylysines, polysulfones, gums, starches, and derivatives thereof. In one embodiment, the starch is a cationic starch. A suitable cationic starch may be formed by reacting a starch, such as corn, maize, waxy maize, potato, and tapioca, and the like, with the reaction product of epichlorohydrin and trialkylamine.

The hydrophobic compounds that are capable of reacting with the hydrophilic polymers include, but are not limited to, alkyl halides, sulfonates, sulfates, and organic acid derivatives. Examples of suitable organic acid derivatives include, but are not limited to, octenyl succinic acid; dodecenyl succinic acid; and anhydrides, esters, and amides of octenyl succinic acid or dodecenyl succinic acid. In certain embodiments, the hydrophobic compounds may have an alkyl chain length of from about 4 to about 22 carbons. For example, where the hydrophobic compound is an alkyl halide, the reaction between the hydrophobic compound and hydrophilic polymer may result in the quaternization of at least some of the hydrophilic polymer amino groups with an alkyl halide, wherein the alkyl chain length is from about 4 to about 22 carbons.

In other embodiments, the hydrophobically modified polymers used in the present invention may be prepared from the polymerization reaction of at least one hydrophilic monomer and at least one hydrophobically modified hydrophilic monomer. Examples of suitable methods of their preparation are described in U.S. Pat. No. 6,476,169, the disclosure of which is incorporated herein by reference in its entirety.

A variety of hydrophilic monomers may be used to form the hydrophobically modified polymers useful in the present invention. Examples of suitable hydrophilic monomers include, but are not limited to homo-, co-, and terpolymers of acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimethylaminopropylmethacrylamide, vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoethyltrimethyl ammonium halide, quaternary salt derivatives of acrylamide, and quaternary salt derivatives of acrylic acid.

A variety of hydrophobically modified hydrophilic monomers also may be used to form the hydrophobically modified polymers useful in the present invention. Examples of suitable hydrophobically modified hydrophilic monomers include, but are not limited to, alkyl acrylates, alkyl methacrylates, alkyl acrylamides, alkyl methacrylamides alkyl dimethylammoniumethyl methacrylate halides, and alkyl dimethylammoniumpropyl methacrylamide halides, wherein the alkyl groups have from about 4 to about 22 carbon atoms. In certain embodiments, the hydrophobically modified hydrophilic monomer comprises octadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumpropyl methacrylamide bromide, 2-ethylhexyl methacrylate, or hexadecyl methacrylamide.

The hydrophobically modified polymers formed from the above-described polymerization reaction may have estimated molecular weights in the range of from about 100,000 to about 10,000,000 and mole ratios of the hydrophilic monomer(s) to the hydrophobically modified hydrophilic monomer(s) in the range of from about 99.98:0.02 to about 90:10. Suitable hydrophobically modified polymers having molecular weights and mole ratios in the ranges set forth above include, but are not limited to, acrylamide/octadecyldimethylammoniumethyl methacrylate bromide copolymer, dimethylaminoethyl methacrylate/hexadecyldimethylammoniumethyl methacrylate bromide copolymer, dimethylaminoethyl methacrylate/vinyl pyrrolidone/hexadecyldimethylammoniumethyl methacrylate bromide terpolymer and acrylamide/2-acrylamido-2-methyl propane sulfonic acid/2-ethylhexyl methacrylate terpolymer.

In other embodiments, the water-soluble relative permeability modifiers comprise a hydrophilically modified polymer. The hydrophilically modified polymers suitable for use with the present invention typically have molecular weights in the range of from about 100,000 to about 10,000,000. In certain embodiments, the hydrophilically modified polymers comprise a polymer backbone, the polymer backbone comprising polar heteroatoms. Generally, the polar heteroatoms present within the polymer backbone of the hydrophilically modified polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous.

In certain embodiments, the hydrophilically modified polymer may be a reaction product of a hydrophilic polymer and a hydrophilic compound. The hydrophilic polymers suitable for forming the hydrophilically modified polymers used in the present invention should be capable of reacting with hydrophilic compounds. In certain embodiments, suitable hydrophilic polymers include, homo-, co-, or terpolymers, such as, but not limited to, polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols), and alkyl acrylate polymers in general. Additional examples of alkyl acrylate polymers include, but are not limited to, polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl propane sulfonic acid/dimethylaminoethyl methacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylaminopropyl methacrylamide). In certain embodiments, the hydrophilic polymers comprise a polymer backbone and reactive amino groups in the polymer backbone or as pendant groups, the reactive amino groups capable of reacting with hydrophilic compounds. In some embodiments, the hydrophilic polymers comprise dialkyl amino pendant groups. In some embodiments, the hydrophilic polymers comprise a dimethyl amino pendant group and at least one monomer comprising dimethylaminoethyl methacrylate or dimethylaminopropyl methacrylamide. In other embodiments, the hydrophilic polymers comprise a polymer backbone comprising polar heteroatoms, wherein the polar heteroatoms present within the polymer backbone of the hydrophilic polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous. Suitable hydrophilic polymers that comprise polar heteroatoms within the polymer backbone include homo-, co-, or terpolymers, such as, but not limited to, celluloses, chitosans, polyamides, polyetheramines, polyethyleneimines, polyhydroxyetheramines, polylysines, polysulfones, gums, starches, and derivatives thereof. In one embodiment, the starch is a cationic starch. A suitable cationic starch may be formed by reacting a starch, such as corn, maize, waxy maize, potato, tapioca, and the like, with the reaction product of epichlorohydrin and trialkylamine.

The hydrophilic compounds suitable for reaction with the hydrophilic polymers include polyethers that comprise halogens; sulfonates; sulfates; and organic acid derivatives. Examples of suitable polyethers include, but are not limited to, polyethylene oxides, polypropylene oxides, and polybutylene oxides, and copolymers, terpolymers, and mixtures thereof. In some embodiments, the polyether comprises an epichlorohydrin-terminated polyethylene oxide methyl ether.

The hydrophilically modified polymers formed from the reaction of a hydrophilic polymer with a hydrophilic compound may have estimated molecular weights in the range of from about 100,000 to about 10,000,000 and may have weight ratios of the hydrophilic polymers to the polyethers in the range of from about 1:1 to about 10:1. Suitable hydrophilically modified polymers having molecular weights and weight ratios in the ranges set forth above include, but are not limited to, the reaction product of polydimethylaminoethyl methacrylate and epichlorohydrin-terminated polyethyleneoxide methyl ether; the reaction product of polydimethylaminopropyl methacrylamide and epichlorohydrin-terminated polyethyleneoxide methyl ether; and the reaction product of poly(acrylamide/dimethylaminopropyl methacrylamide) and epichlorohydrin-terminated polyethyleneoxide methyl ether. In some embodiments, the hydrophilically modified polymer comprises the reaction product of a polydimethylaminoethyl methacrylate and epichlorohydrin-terminated polyethyleneoxide methyl ether having a weight ratio of polydimethylaminoethyl methacrylate to epichlorohydrin-terminated polyethyleneoxide methyl ether of about 3:1.

In yet other embodiments, the water-soluble relative permeability modifiers comprise a water-soluble polymer without hydrophobic or hydrophilic modification. Examples of suitable water-soluble polymers without hydrophobic or hydrophilic modification include, but are not limited to, homo-, co-, and terpolymers of acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimethylaminopropylmethacrylamide, vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoethyltrimethyl ammonium halide, quaternary salt derivatives of acrylamide, and quaternary salt derivatives of acrylic acid.

In an embodiment, a hydrocarbon reservoir in a subterranean formation may have one or more producing wells. In addition, the hydrocarbon reservoir may have one or more injection wells for providing a fluid source to supply a driving force for the production of hydrocarbons. As used herein, a “fluid source” refers to any source of one or more fluids that flow through the subterranean formation between perforations or fractures in an individual wellbore or between separate wellbores. An injection wells may be drilled for the specific purpose of injecting fluids to provide the fluid source, or an existing wellbore may be converted from producing wells to injecting wells. In another embodiment, a natural fluid source that provides a driving force may be present in the subterranean formation in the form of existing water, external water entering the reservoir, or natural gas pressure within the subterranean formation. Alternatively, water may flow into the subterranean formation from a nearby water source (e.g., an edge water aquifer) to create a fluid source that provides a driving force within the subterranean formation. In this case, the subterranean formation may not require injection wells for the production of hydrocarbons.

The flow of hydrocarbon fluids within the reservoir may be modified through the use of an in-situ barrier comprising a fracture containing a sealant. The use of an in-situ barrier with selective or non-selective barriers to flow may be used to modify the flow pattern within an entire reservoir. In an embodiment, a relative permeability modifier may allow oil to selectively flow through the in-situ barrier in relation to an aqueous fluid. In another embodiment, a plurality of in-situ barriers may have varying permeabilities, whose placement and geometries, may act as a series of barriers or baffles to guide the flow of at least one desired fluid to a producing well. Without intending to be limited by theory, it is believed that a plurality of selectively placed fractures with selective or non-selective barriers to fluid flow may be used to modify the flow regime inside the hydrocarbon reservoir to improve the volumetric sweep efficiency of the hydrocarbons in the formation. Further, the sealant and fluid used to provide the driving force for flow and sweep of the hydrocarbon fluids can be selected to maximize the amount of hydrocarbons recovered in a hydrocarbon reservoir. The flow patterns within a hydrocarbon reservoir may be determined through the use of a simulator program using any simulator capable of calculating the flow regime within a subterranean environment. Suitable simulators for use in hydrocarbon reservoirs are known to those skilled in the art.

In an embodiment shown in FIG. 1, an injection well 124 may be drilled remote from, but generally parallel to, existing well 110. In an embodiment, wellbore 110 may be drilled for the purpose of modifying the flow pattern of at least one fluid within the subterranean reservoir. In one certain embodiment, injection well 124 is drilled proximate the sealed fractures 118, 120. As those of ordinary skill in the art will appreciate, the injection well 124 can alternatively be formed prior to the formation of the wellbore 110, or may be a converted producing wellbore. Once the injection well 124 has been formed and the selected fracture or fractures 118, 120 sealed, flood fluid can be pumped down the injection well 124. As the flood fluid is pumped into the reservoir 112 it forms a propagating flood front. The flood front may be diverted around the sealed fracture 120. At the same time, hydrocarbons are drained into fractures 128. As the producing fracture 128 begins producing high rates of flood fluid, it may be sealed. A bridge plug or other zonal isolation device may be installed in the wellbore 110 just uphole of the fracture 128 when the fracture is sealed. A new producing fracture may then be created to further produce hydrocarbons from the hydrocarbon reservoir. This isolation process is repeated as sufficiently high flood fluid ratios are being produced from successive transverse fractures until all of the transverse fractures have been sealed.

In an embodiment, the flow of the fluids in a hydrocarbon reservoir may be modified on a field-wide basis. The injection well 124 may be located in an existing injection pattern as known to those of ordinary skill in the art. For example, existing 5-spot, 7-spot, or line drive injection patterns may have existing injection wells for use in this method. As will be appreciate by those of ordinary skill in the arts, the selection of a wellbore for use as an injection well may change during the life of the hydrocarbon reservoir. The producing wellbore 110 may be an existing wellbore or may be drilled for the purpose of recovering fluids. In another embodiment, the wellbore 110 and any fractures associated with the wellbore 110 may be drilled or used for the purpose of modifying the flow pattern of at least one fluid within a subterranean reservoir without being used to produce a fluid. The selection of fractures or locations for creating new fractures may be chosen so as to increase the sweep efficiency of fluids moving through the formation.

In one exemplary variant of the method illustrated in FIG. 1, the fracture 120 may only be partially sealed in the near wellbore area rather than completely sealed all the way to its tip. The benefit of sealing the near wellbore area is that if the injection fluid happens to move faster in this area the flow of injection fluid can be partially diverted to improve sweep.

Turning to FIG. 2, another embodiment of the method for increasing hydrocarbon production in accordance with the present invention is disclosed. In this embodiment, the flood fluid is introduced into the reservoir 212 through a tubing 260, which is installed into wellbore 224 rather than a separate injection well. The tubing 260 injects the flood fluid into the reservoir 212 from the toe 240 of the wellbore 224, which may include one or more fractures 242 through which the fluid is injected into the formation. Hydrocarbons may be produced through one or more fractures 290 up the annulus 265 formed between the tubing 260 and the casing 262. Packer 270 may be used to seal the end of the tubing 260, so the flood fluid does not enter into the annulus 265. In this embodiment, additional wellbores 210, 280 may be used to produce fluids which may be driven at least in part by the fluids injected from wellbore 224. These additional wellbores may have one or more fractures 286, 288 with a sealant composition 222 placed therein to affect the flow pattern in the hydrocarbon reservoir. As will be appreciated by one of ordinary skill in the art, a plurality of fractures of various shapes may be used to affect the flow of fluids within the hydrocarbon reservoir. In another embodiment, the wellbores 210, 280 and any fractures associated with the wellbores (e.g., fractures 286, 288) may be drilled or used for the purpose of modifying the flow pattern of at least one fluid within a subterranean reservoir without being used to produce a fluid. In this embodiment, additional wellbore (not shown in FIG. 2) may be used to produce one or more fluids from the subterranean reservoir.

Once the flood fluid ratio reaches a sufficiently high value, the fractures used for production 290 may be sealed using the techniques described above and new production fractures or perforations may be created. This process may be repeated for successive fractures as the flood front 216 moves into the area near a producing well.

Also disclosed herein is a system that may be useful for increasing the production of hydrocarbons and/or reducing the production of water from a subterranean formation. The system generally comprises a fluid source within a subterranean formation for providing a fluid driving force within the subterranean formation, a wellbore disposed in the subterranean formation for producing a production fluid from the subterranean formation, and an in-situ barrier disposed within the subterranean formation, where the in-situ barrier modifies the flow of at least one fluid driven by the fluid driving force within the subterranean formation. Each component of the system is as described above and may include any of the optional features disclosed herein. As those of ordinary skill in the art will appreciate from the disclosure, there are many different ways of arranging and providing the wells, the in-situ barriers to flow, and the fluid provided by the fluid source, and many different ways of recovering the hydrocarbons from the reservoir.

To facilitate a better understanding of the present invention, the following examples of certain aspects of some embodiments are given. In no way should the following examples be read to limit, or define, the scope of the invention.

Example 1

A reservoir simulation is used to simulate an in-situ barrier placed in a subterranean formation using a horizontal well for this prophetic example. One such simulator is a numerical finite difference simulator QuikLook version 4.1 provided by Halliburton Energy Services, Inc. The horizontal well has a production length of about 1560 ft. Input properties for the subterranean formation simulation include: Area of 2600 ft by 2600 ft., thickness of 490 ft with an average formation porosity of 0.24, horizontal permeability in the longitudinal direction of 30 md, horizontal permeability in the latitudinal direction of 45 md and vertical permeability of 3 md. The initial water saturation in the oil zone is 0.37. There is an active edge and bottom-water aquifer as the source of encroaching water flow to the producing well.

FIG. 3 depicts a water saturation profile in the formation after 911.476 days without an in-situ barrier using the reservoir simulation. Water saturation is shown on a scale of 0.00 to 1.00 with 1.00 being 100% water saturation. The water saturation scale is shown in the sidebar. The simulation results show that the water front is beginning to break through to the production well.

For comparison, FIG. 4 depicts a water saturation profile in the formation after 914.01 days with an in-situ barrier using the reservoir simulation. The simulation results show that the water front is being effectively blocked from the production well. Water saturation, at about 914 days, is lower at the horizontal production well than in the case without an in-situ barrier. The increased sweep of the water is expected to result in an increased production of hydrocarbons from the well.

FIG. 5 and FIG. 6 depict the total oil production and total water production for both the base case without an in-situ barrier and the comparison case with the in-situ barrier depicted in FIG. 4. The figures show the production of water is greater (line 508) and the production of oil lower (line 502) without an in-situ barrier as compared to the production of water (line 506) and the production of oil (line 504) with an in-situ barrier. The increase in oil production is about 5.4% and the decrease in water production is about 6.41%. The increase in oil production is worth millions of dollars and the decline in water production represents a significant savings in the cost of waste water disposal.

Example 2

The same reservoir simulation described above in Example 1, is used to simulate an injector and a producer in a line drive configuration for this prophetic example. A well is located between the injector and producer and is used to dispose an in-situ barrier into the formation.

FIG. 7 depicts a side view of a water saturation profile in the formation after about 3,614 days with an in-situ barrier using the reservoir simulation. The simulation results show that the water front is effectively slowed down by the in-situ barrier between the injector and producer. FIG. 8 depicts an aerial view of the water saturation profile shown in FIG. 7. FIG. 8 similarly depicts that the water front is forced to move around the in-situ barrier in the formation in order to reach the producing well.

FIG. 9 and FIG. 10 depict the total oil production and total water production for the simulation shown in FIG. 7 and FIG. 8. In addition to the simulation results shown in FIG. 7 and FIG. 8, FIG. 9 and FIG. 10 show the results for a simulation without an in-situ barrier between the producer and injector and for a case in which the in-situ barrier is moved closer to the producing well. FIG. 9 shows the production of oil is less without an in-situ barrier (line 510) than either the case with an in-situ barrier (line 514) or the closer in-situ barrier (line 512). FIG. 10 shows the production of water is greater without an in-situ barrier (line 520) than either the case with an in-situ barrier (line 516) or the closer in-situ barrier (line 518). The results indicate that over about a 20 year production (about 7,300 days), the total oil production can be increased by over 20% and the total water production can be reduced by over about 40%. As one of ordinary skill in the art would understand, this represents a significant increase in the production of oil from the reservoir and a significant reduction in the amount of waste water that must be processed and disposed.

Example 3

The same reservoir simulation described above in Example 1, is used to simulate a reservoir with a 5-spot well configuration for this prophetic example. In this example, a well with an in-situ barrier is modeled between the injector and a producer.

FIG. 11 depicts an aerial view of a water saturation profile in the formation after about 6,378 days with an in-situ barrier using the reservoir simulation. The simulation results show that the water front is effectively forced to flow around the in-situ barrier between the injector and producer. FIG. 12 depicts an aerial view of the water saturation profile for the configuration shown in FIG. 11 without an in-situ barrier. FIG. 11 shows that the water front is further advanced without the in-situ barrier between the injection well and production well.

FIG. 13 and FIG. 14 depict the total oil production and total water production for the simulations shown in FIG. 11 and FIG. 12. FIG. 13 shows the production of oil is less without an in-situ barrier (line 522) than the case with an in-situ barrier (line 524). FIG. 14 shows the production of water is greater without an in-situ barrier (line 528) than the case with an in-situ barrier (line 526). The results indicate that over about a 20 year production, the total oil production can be increased by about 9% and the total water production can be reduced by about 8% through the use of an in-situ barrier. As one of ordinary skill in the art would understand, this represents a significant increase in the production of oil from the reservoir and a significant reduction in the amount of waste water that must be processed and disposed.

Example 4

The same reservoir simulator described above in Example 1, is used to simulate an in-situ barrier comprising a relative permeability modifier for this prophetic example. The relative permeability modifier comprises a compound that is capable of reducing the permeability of a subterranean formation to aqueous-based fluids without substantially changing its permeability to hydrocarbons, as described above. The model also assumes a change in the wettability of the fracture to be preferentially oil-wet in the fracture creating a capillary barrier to the entry of an aqueous fluid. The parameters are essentially the same as for Example 1 with the additional inclusion of a high-permeability channel of 500 md.

In this example, the flow of an aqueous fluid from a strong edge-water aquifer into a formation penetrated by a horizontal well is modeled. The horizontal well is modeled in a high permeability channel in order to simulate a high influx of oil. Such a channel also acts as a conduit for the influx of an aqueous fluid.

Three cases are used to model the results of about 2,000 days of production. The first case represented a base production case with no in-situ barrier. The second case represented an in-situ barrier that blocked both oil and water. The permeability of the in-situ barrier is set at 1×10⁻⁶ millidarcy (md) for the second case. Finally, the third case represented an in-situ barrier using a relative permeability modifier that selectively blocks the flow of an aqueous fluid relative to oil and affects the oil-wet state of the formation. For the third case, the absolute permeability of the in-situ barrier is set at 1 md.

FIG. 15 depicts an aerial view of a permeability profile in the formation with respect to the horizontal wellbore and the high-permeability channel. FIG. 16 depicts an aerial view of the water saturation profile for the first case with no in-situ barrier. This first case demonstrates the channeling of water along the high permeability channel. FIG. 17 depicts an aerial view of a water saturation profile for the second case comprising an in-situ barrier. The simulation results show the coning of water around the in-situ barrier and flowing along the high permeability channel to the well bore. FIG. 18 depicts an aerial view of a water saturation profile for the third case with an in-situ barrier comprising a relative permeability modifier. The simulation results show the flow of water blocked by the in-situ barrier and a lack of coning due to the ability of the oil to flow through the barrier but not the aqueous fluid.

The resulting cumulative production values after about 2,000 days of oil and water (in millions of barrels or MMBBL) are: 12.8 MMBBL of oil and 7.1 MMBBL of water for the first case with no in-situ barrier, 17.1 MMBBL of oil and 2.8 MMBBL of water for the second case with an in-situ barrier, and 18.7 MMBBL of oil and 1.3 MMBBL of water for the third case with an in-situ barrier comprising a relative permeability modifier. This example shows potential to “design” the absolute permeability, relative permeability, and capillary pressure within a subterranean formation to baffle water, while allowing oil to more preferentially flow through the in-situ barrier to a producing well. As one of ordinary skill in the art would understand, this represents a significant increase in the production of oil from the reservoir and a significant reduction in the amount of waste water that must be processed and disposed.

Example 5

Using the same simulation as described in Example 1 using a horizontal well with edge water drive, an in-situ barrier is modeled using a partial flow barrier for this prophetic example. The production is for about 4,000 days. No high permeability streak is present in the model. Four cases were modeled to determine the difference between the various types of in-situ barriers. The first case was the base case without an in-situ barrier. In the second case, a partial barrier is modeled having a permeability of 1md and a relative permeability modifier is not present. In the third case, a partial barrier is modeled having a permeability of 1md and a relative permeability modifier is present. In the fourth case, the in-situ barrier comprised a full barrier to the flow of fluids.

The resulting cumulative production values after about 4,000 days of oil and water (in millions of barrels or MMBBL) are: 28.8 MMBBL of oil and 11.2 MMBBL of water for the first case with no in-situ barrier, 30.4 MMBBL of oil and 9.6 MMBBL of water for the second case with an in-situ partial barrier, 30.7 MMBBL of oil and 9.3 MMBBL of water for the third case with an in-situ partial barrier comprising a relative permeability modifier, and 30.7 MMBBL of oil and 9.3 MMBBL of water for the fourth case with an in-situ barrier comprising full barrier to flow. As one of ordinary skill in the art would understand, this represents a significant increase in the production of oil from the reservoir and a significant reduction in the amount of waste water that must be processed and disposed.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted. 

1. A method comprising: providing a fluid source in a subterranean formation; providing a wellbore in the subterranean formation; and providing an in-situ barrier, wherein the in-situ barrier is disposed within the subterranean environment and modifies the flow pattern of at least one fluid within the subterranean formation that is provided by the fluid source and flows towards the wellbore.
 2. The method of claim 1 wherein the in-situ barrier comprises a fracture with a sealant disposed therein.
 3. The method of claim 2 wherein the in-situ barrier is a non-selective barrier.
 4. The method of claim 3 wherein the sealant comprises at least one composition selected from the group consisting of: a cement, a linear polymer mixture, a linear polymer mixture with a cross-linker, an in-situ polymerized monomer mixture, a resin-based fluid, an epoxy based fluid, a magnesium based slurry, a drilling mud, drilling cuttings, slag, a clay based slurry, an emulsion, a precipitate, an in-situ precipitate, and any combination thereof.
 5. The method of claim 3 wherein the sealant comprises a swellable elastomer that swells in the presence of an aqueous-based fluid and an oil-based fluid, wherein the sealant comprises at least one swellable elastomer selected from the group consisting of: an ethylene propylene rubber, an ethylene-propylene-diene terpolymer rubber, a butyl rubber, a brominated butyl rubber, a chlorinated butyl rubber, a chlorinated polyethylene, a neoprene rubber, a styrene butadiene copolymer rubber, a sulphonated polyethylene, an ethylene acrylate rubber, an epichlorohydrin ethylene oxide copolymer, a silicone rubber, a fluorosilicone rubber, and any combination thereof.
 6. The method of claim 2 wherein the in-situ barrier is a selective barrier.
 7. The method of claim 6 wherein the sealant comprises a swellable elastomer that swells in the presence of an aqueous-based fluid, wherein the sealant comprises at least one swellable elastomer selected from the group consisting of: a starch-polyacrylate acid graft copolymer, a polyvinyl alcohol cyclic acid anhydride graft copolymer, a polyacrylamide, poly(acrylic acid-co-acrylamide), a poly(2-hydroxyethyl methacrylate), a poly(2-hydroxypropyl methacrylate), an isobutylene maleic anhydride, an acrylic acid type polymers, a vinylacetate-acrylate copolymer, a polyethylene oxide polymer, a carboxymethyl cellulose type polymer, a starch-polyacrylonitrile graft copolymer, a polymer comprising a swelling clay mineral, a polymer comprising a salt, and any combination thereof.
 8. The method of claim 6 wherein the sealant comprises a swellable elastomer that swells in the presence of an oil-based fluid, wherein the sealant comprises at least one swellable elastomer selected from the group consisting of: a natural rubber, an acrylate butadiene rubber, an isoprene rubber, a chloroprene rubber, a butyl rubber, a brominated butyl rubber, a chlorinated butyl rubber, a chlorinated polyethylene, a neoprene rubber, a styrene butadiene copolymer rubber, a chlorinated polyethylene, a sulphonated polyethylene, an ethylene acrylate rubber, an epichlorohydrin ethylene oxide copolymer, an epichlorohydrin terpolymer, an ethylene-propylene rubber, an ethylene vinyl acetate copolymer, an ethylene-propylene-diene terpolymer rubber, an ethylene vinyl acetate copolymer, a nitrile rubber, an acrylonitrile butadiene rubber, a hydrogenated acrylonitrile butadiene rubber, a carboxylated high-acrylonitrile butadiene copolymer, a polyvinylchloride-nitrile butadiene blend, a fluorosilicone rubber, a silicone rubber, a poly 2,2,1-bicyclo heptene, an alkylstyrene, a polyacrylate rubber, an ethylene-acrylate terpolymer, a fluorocarbon polymer, a copolymers of poly(vinylidene fluoride) and hexafluoropropylene, a terpolymer of poly(vinylidene fluoride)-hexafluoropropylene-tetrafluoroethylene, a terpolymer of poly(vinylidene fluoride)-polyvinyl methyl ether-tetrafluoroethylene, a perfluoroelastomer, a highly fluorinated elastomer, a butadiene rubber, a polychloroprene rubber, a polyisoprene rubber, a polysulfide rubber, a polyurethane, a silicone rubber, a vinyl silicone rubber, a fluoromethyl silicone rubber, a fluorovinyl silicone rubber, a phenylmethyl silicone rubber, a styrene-butadiene rubber, a copolymer of isobutylene and isoprene, a brominated copolymer of isobutylene and isoprene, a chlorinated copolymer of isobutylene and isoprene, and any combination thereof.
 9. The method of claim 6 wherein the sealant comprises a relative permeability modifier.
 10. The method of claim 9, wherein the relative-permeability modifier comprises a water-soluble polymer, wherein the water-soluble polymer comprises a hydrophobically modified polymer, wherein the hydrophobically modified polymer comprises a polymer backbone and a hydrophobic branch, and wherein the hydrophobic branch comprises an alkyl chain of about 4 to about 22 carbons.
 11. The method of claim 9, wherein the relative-permeability modifier comprises a hydrophobically modified polymer, wherein the relative-permeability modifier comprises a reaction product of at least one hydrophobic compound and at least one hydrophilic polymer.
 12. The method of claim 9, wherein the relative-permeability modifier comprises a hydrophobically modified polymer synthesized from a polymerization reaction that comprises a hydrophilic monomer and a hydrophobically modified hydrophilic monomer, wherein the hydrophobically modified polymer comprises a hydrophobic branch, and wherein the hydrophobic branch comprises an alkyl chain of about 4 to about 22 carbons.
 13. The method of claim 9, wherein the relative-permeability modifier comprises a hydrophilically modified polymer, wherein the hydrophilically modified polymer is water soluble.
 14. A method comprising: providing a plurality of wellbores in a subterranean formation, wherein at least one wellbore comprises a fracture; providing at least one injection wellbore in the subterranean formation; and providing an in-situ barrier by disposing a sealant in the fracture of the at least one wellbore wherein the sealant modifies the flow pattern of at least one fluid provided by the injection wellbore within the subterranean formation.
 15. The method of claim 14 wherein the in-situ barrier is a selective barrier.
 16. The method of claim 15 wherein the in-situ barrier is a non-selective barrier.
 17. The method of claim 15 wherein the sealant comprises at least one sealant selected from the group consisting of: a swellable elastomer that swells in the presence of an aqueous-based fluid, a swellable elastomer that swells in the presence of an oil-based fluid, and a relative permeability modifier.
 18. A system comprising: a fluid source within a subterranean formation for providing a fluid driving force within the subterranean formation; a wellbore disposed in the subterranean formation for producing a production fluid from the subterranean formation; and an in-situ barrier disposed within the subterranean formation, wherein the in-situ barrier modifies the flow of at least one fluid driven by the fluid driving force within the subterranean formation.
 19. The system of claim 18 wherein fluid source comprises an injection well.
 20. The system of claim 18 wherein the fluid source comprises a natural fluid source, wherein the natural fluid source comprises at least one fluid source selected from the group consisting of: existing water in the subterranean formation, external water entering the subterranean formation, natural gas pressure within the subterranean formation, and any combination thereof.
 21. The system of claim 18 further comprising a plurality of in-situ barriers disposed within the subterranean formation, wherein the plurality of in-situ barriers form a baffle that guides the at least one fluid driven by the fluid driving force.
 22. The system of claim 18 wherein the in-situ barrier comprises a fracture with sealant disposed therein.
 23. The system of claim 22 wherein the sealant comprises at least one sealant selected from the group consisting of: a swellable elastomer that swells in the presence of an aqueous-based fluid, a swellable elastomer that swells in the presence of an oil-based fluid, and a relative permeability modifier. 